Coiled tubing is used in maintenance tasks on completed oil and gas wells and drilling of new wells. End connectors can be used to attach tools, such as a drill motor with bit, jetting nozzles, packers, etc, to the end of the coiled tubing. The tools can then be run into the well and operated on the coiled tubing.
There are two basic types of end connectors for coiled tubing: internal connectors, such as dimple connectors; and external connectors, such as grapple connectors. Internal connectors include a shaft that fits inside the end of the coiled tubing. The coiled tubing can then be crimped to provide a dimpled profile for the pipe and the internal shaft so that the connector grips tight and will not come off the coiled tubing.
External connectors are often used for deploying tools into wells. External connectors include, for example, “grapple connectors” or “slip connectors”. They have an external housing that contains profiled segments with teeth that bite into the outside of coiled tubing, thereby holding the external connector in place on the coiled tubing. One grapple connector is known to include both an outer housing and an inner sleeve. The inner sleeve supports the coiled tubing and allows the teeth of the outer housing to bite more firmly into the end of the coiled tubing when the outer sleeve is tightened around the end of the coiled tubing, thereby improving the connection between coiled tubing and connector. This grapple connector is made by BJ Services Company LLC, and is marketed under the name GRAPPLE FM CONNECTOR™.
When running a tool attached to coiled tubing via internal or external connectors, there is a risk that the tool will get stuck in the well. To address this problem, coiled tubing downhole tool assemblies that have a diameter greater than that of the coiled tubing often include a hydraulic disconnect. The hydraulic disconnect is attached between the end connector and the tool and includes a piston held in place by a shear pin. In the event the tool becomes stuck, a ball can be pumped down through the coiled tubing and into the hydraulic disconnect. The ball lands on a ball seat of the piston thereby blocking flow through the coiled tubing. Sufficient hydraulic pressure can then be applied to sheer the sheer pin, allowing the piston to slide down and disengage the ‘dogs’ holding the tool together with the result that the tool disconnects from the coiled tubing.
However, in some cases the coiled tubing remains stuck after disconnecting the tool. For example, this can occur where the coiled tubing is hung up in the well at the end connector. A solution for this problem is to kill the well and cut the coiled tubing on surface. A severing tool can then be run from the surface through the coiled tubing on electric line. The severing tool can be, for example, a plasma cutting tool or a shaped explosive charge, which is used to cut the coiled tubing above the end connector, thereby freeing the coiled tubing. However, this solution is problematic for several reasons. Killing the well can potentially cause damage to the well, is time consuming, and results in lost production until the well is brought back on stream. Further, cutting the coiled tubing string at the surface can potentially render the string too short to be reused in the well, thereby requiring deployment of a new tubing string, which can be costly.
Other devices that are generally well known in the art for use in coiled tubing include pigs and darts. Pigs and darts can be pumped through the coiled tubing to accomplish, for example, the cleaning of unwanted debris from inside of the coiled tubing. Darts are sometimes used during well completions when pumping cement. After the cement is pumped into well through the coiled tubing, a dart can be inserted and then water can be employed to hydraulically push the dart and cement to displace the cement out of the coil. It is well known that the dart can include a frangible disc positioned in a flowpath through the center of the dart. It is also well known that a polyurethane fin or seal can be positioned around the outer circumference of the dart. After displacing the cement, the pig/dart lands on an internal connector positioned at the end of the coiled tubing and seals off any further flow. The coiled tubing can then be pulled free from the cement without fear that displacement fluid might contaminate the cement slurry. Subsequently the coiled tubing can be pressured up sufficiently to burst the frangible disc and thereby reestablish flow through the coiled tubing. However pigs and darts are not known for use in solving the problem of a coiled tubing tool assembly stuck in a well.
Using sand slurries for erosive perforating and/or slotting of well casing is well known in the art. Typically the sand slurry can be water with approximately 5% by volume of sand. The sand slurry base fluid, which is water, can preferably have a light loading of gelling agent to help suspend the sand in the surface mixing apparatus and provide fluid friction pressure reduction when pumping the sand slurry into the well. Alternatively, a conventional friction reducer and surface mixing equipment can be used in place of the gel.
The cutting darts and other cutting assemblies and methods of the present disclosure may reduce or eliminate one or more of the problems discussed above.